Systems and methods for determining the strain experienced by wellhead tubulars

ABSTRACT

A system includes a tubular member ( 60 ) including a radially outer surface ( 60   c ) and a sensor assembly ( 128 ). The sensor assembly includes a strain sensor coupled to the radially outer surface. In addition, the sensor assembly includes a first coating having ( 134 ) a first hardness and a first tensile strength. The first coating encases the strain sensor ( 131,130 ) and at least part ( 64 ) of the outer surface. Further, the sensor assembly includes a second coating ( 136 ) having a second hardness that is greater than the first hardness and a second tensile strength that is greater than the first tensile strength. The second coating encases the first coating and at least another part ( 68 ) of the radially outer surface.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent applicationSer. No. 62/149,096 filed Apr. 17, 2015, and entitled “Systems andMethods for Determining the Strain Experienced by Wellhead Tubulars,”which is hereby incorporated herein by reference in its entirety for allpurposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

Embodiments disclosed herein relate generally to oil and gas wells. Moreparticularly, embodiments disclosed herein relate to systems and methodsfor measuring the strain experienced by tubular members employed in oiland gas wells.

In drilling operations, a large diameter hole is drilled from thesurface to a selected depth. Then, a primary conductor secured to thelower end of an outer wellhead housing disposed at the surface, alsoreferred to as a low pressure housing, is run into the borehole. Cementis pumped down the primary conductor and allowed to flow back up theannulus between the primary conductor and the borehole sidewall.Alternatively, the primary conductor is jetted into place (i.e., nocement is used).

With the primary conductor secured in place, a drill bit is loweredthrough the primary conductor to drill the borehole to a second depth.Next, an inner wellhead housing, also referred to as a high pressurehousing, is seated in the upper end of the outer wellhead housing. Astring of casing secured to the lower end of the inner wellhead housingor seated in the inner wellhead housing extends downward through theprimary conductor. Cement is pumped down the casing string, and allowedto flow back up the annulus between the casing string and the primaryconductor to secure the casing string in place. The drill bit is loweredthrough the primary conductor and the casing string and drillingcontinues.

Prior to continuing drilling operations in greater depths, a blowoutpreventer (BOP) is mounted to the wellhead, and in subsea environments,a lower marine riser package (LMRP) is mounted to the BOP. The drillstring is suspended from the rig through the BOP (and LMPR in offshoreoperations) into the well bore. Drilling generally continues whilesuccessively installing concentric casing strings that line theborehole. Each casing string is cemented in place by pumping cement downthe casing and allowing it to flow back up the annulus between thecasing string and the borehole sidewall.

Following drilling operations, the cased well is completed (i.e.,prepared for production). Typically, a production tree is installed onthe wellhead during completion operations and production tubing is runthrough the casing and suspended by a tubing hanger seated in a matingprofile in the inner wellhead housing or production tree.

During drilling and production operations, the main function of theprimary conductor is to resist axial and lateral loads imposed at thewellhead. Such loads can be particularly large in offshore operationswhere a relatively large, heavy stack of equipment (e.g., productiontree, BOP, LMRP) is mounted atop the wellhead and is subjected to subseacurrents. As a result, the primary conductor typically experiences asignificant amount of strain. In extreme scenarios, the strain may besufficient to damage the primary conductor (either through fatigue orsome other failure modality).

BRIEF SUMMARY OF THE DISCLOSURE

Some embodiments disclosed herein are directed to a conductor for use inoil and gas wells. In an embodiment, the conductor includes a tubularmember with a radially outer surface, and a sensor assembly. The sensorassembly includes a strain sensor coupled to the outer surface. Inaddition, the sensor assembly includes a first coating having a firsthardness and a first tensile strength and encasing the sensor and atleast part of the outer surface. Further, the sensor assembly includes asecond coating having a second hardness that is greater than the firsthardness, a second tensile strength that is greater than the firsttensile strength. The second coating encases the first coating and atleast another part of the outer surface.

Other embodiments disclosed herein are directed to a system. In anembodiment, the system includes a wellhead and a tubular memberconfigured to be coupled to the wellhead and to extend into a wellbore.The tubular member has a radially outer surface. In addition, the systemincludes a first strain sensor coupled to the radially outer surface andan outer coating disposed over the first strain sensor. Further, thesystem includes a communication unit in communication with the firststrain sensor and a remote surface location.

Other embodiments disclosed herein are directed to a method formanufacturing a conductor for use in an oil and gas well. In anembodiment, the method includes (a) coupling a first strain sensor to aradially outer surface of the conductor. The first strain sensor isconfigured to measure the strain on outer surface. In addition, themethod includes (b) encasing the first sensor with a first coatinghaving a first hardness and a first tensile strength after (a). Further,the method includes (c) encasing the first coating with a second coatingafter (b). The second coating has a second hardness that is greater thanthe first hardness and a second tensile strength that is greater thanthe first tensile strength.

Other embodiments disclosed herein are directed to a method of measuringstrain on a first conductor for use in an oil and gas well. In anembodiment, the method includes (a) measuring a strain on the firstconductor with a first strain sensor coupled to a radially outer surfaceof the first conductor. In addition, the method includes (b) protectingthe first strain sensor during (a) with an outer coating. Further, themethod includes (c) routing data from the first strain sensor to acommunication unit after (a). Still further, the method includes (d)wirelessly communicating with a remote surface location with thecommunication unit after (c).

Still other embodiments disclosed herein are directed to a system. In anembodiment, the system includes a tubular member including a radiallyouter surface. In addition, the system includes a sensor assembly. Thesensor assembly includes a strain sensor coupled to the radially outersurface of the tubular member. In addition, the sensor assembly includesa first coating having a first hardness and a first tensile strength.The first coating encases the strain sensor and at least part of theradially outer surface of the tubular member. Further, the systemincludes a second coating having a second hardness that is greater thanthe first hardness and a second tensile strength that is greater thanthe first tensile strength. The second coating encases the first coatingand at least another part of the radially outer surface.

Embodiments described herein comprise a combination of features andadvantages intended to address various shortcomings associated withcertain prior devices, systems, and methods. The foregoing has outlinedrather broadly the features and technical advantages of the invention inorder that the detailed description of the invention that follows may bebetter understood. The various characteristics described above, as wellas other features, will be readily apparent to those skilled in the artupon reading the following detailed description, and by referring to theaccompanying drawings. It should be appreciated by those skilled in theart that the conception and the specific embodiments disclosed may bereadily utilized as a basis for modifying or designing other structuresfor carrying out the same purposes of the invention. It should also berealized by those skilled in the art that such equivalent constructionsdo not depart from the spirit and scope of the invention as set forth inthe appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of various exemplary embodiments, referencewill now be made to the accompanying drawings in which:

FIG. 1 is a schematic side view of an offshore system in accordance withthe principles disclosed herein for drilling and/or producing from asubsea wellbore;

FIG. 2 is an enlarged partial cross-sectional view of the offshoresystem and strain monitoring system of FIG. 1;

FIG. 3 is a cross-sectional view of the offshore system of FIG. 1 takenalong section III-III in FIG. 2;

FIG. 4 is an enlarged cross-sectional view of one of the sensorassemblies of FIG. 2;

FIG. 5 is an enlarged perspective view of the conductor of FIG. 1illustrating the sensor array of the monitoring system of FIG. 2;

FIG. 6 is a schematic, partial cross-sectional view of the outer coatingof the sensor assemblies of FIG. 2 being applied to the conductor;

FIG. 7 is a schematic cross-sectional view of the conductor of FIG. 1illustrating an external gauge ring mounted thereto;

FIGS. 8 and 9 are sequential schematic side views illustrating theinstallation of the conductor of FIG. 1;

FIG. 10 is a schematic side cross-sectional view of an offshore systemin accordance with the principles disclosed herein for drilling and/orproducing from a subsea wellbore;

FIG. 11 is a top cross-sectional view taken along section XI-XI of FIG.10; and

FIG. 12 is an enlarged cross-sectional view of section XII-XII of FIG.10.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments.However, one skilled in the art will understand that the examplesdisclosed herein have broad application, and that the discussion of anyembodiment is meant only to be exemplary of that embodiment, and notintended to suggest that the scope of the disclosure, including theclaims, is limited to that embodiment.

Certain terms are used throughout the following description and claimsto refer to particular features or components. As one skilled in the artwill appreciate, different persons may refer to the same feature orcomponent by different names. This document does not intend todistinguish between components or features that differ in name but notfunction. The drawing figures are not necessarily to scale. Certainfeatures and components herein may be shown exaggerated in scale or insomewhat schematic form and some details of conventional elements maynot be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and“comprising” are used in an open-ended fashion, and thus should beinterpreted to mean “including, but not limited to . . . .” Also, theterm “couple” or “couples” is intended to mean either an indirect ordirect connection. Thus, if a first device couples to a second device,that connection may be through a direct connection, or through anindirect connection via other devices, components, and connections. Inaddition, as used herein, the terms “axial” and “axially” generally meanalong or parallel to a central axis (e.g., central axis of a body or aport), while the terms “radial” and “radially” generally meanperpendicular to the central axis. For instance, an axial distancerefers to a distance measured along or parallel to the central axis, anda radial distance means a distance measured perpendicular to the centralaxis. As used herein, the term “well site personnel” is used broadly toinclude any individual or group of individuals who may be disposed orstationed on a rig or worksite or offsite at a remote monitoringlocation (such as a remote office location). The term also would includeany personnel involved in the drilling and/or production operations ator for an oil and gas well such as, for example, technicians, operators,engineers, analysts, etc.

Referring now to FIG. 1, an embodiment of an offshore system 10 fordrilling and/or producing a subsea wellbore 11 is shown. In thisembodiment, system 10 includes an offshore platform 20 at the seasurface 12, a subsea blowout preventer (BOP) 30 mounted to a wellhead 40at the sea floor 13, and a lower marine riser package (LMRP) 50 mountedto BOP 30. Platform 20 is equipped with a derrick 21 that supports ahoist (not shown). A drilling riser 25 extends from platform 20 to LMRP50. In general, riser 25 is a large-diameter pipe that connects LMRP 50to the floating platform 20. During drilling operations, riser 25 takesmud returns to the platform 20.

A primary conductor 60, also referred to as conductor 60, is coupled toand extends from wellhead 40 into subterranean wellbore 11. Conductor 60is a tubular member including a central or longitudinal axis 65, a firstor upper end 60 a coupled to wellhead 40, a second or lower end (notshown) disposed within the wellbore 11, a radially outer surface 60 cextending axially between from end 60 a, and a radially inner surface 60d also extending axially from end 60 a. Inner surface 60 d defines athroughbore 62 for receiving other components extending into and/orrouted within wellbore (e.g., tubing, drill pipe, casing pipe, drillbits, downhole tools, etc.). During drilling and/or productionoperations, the primary function of conductor 60 is to resist axial andlateral loads applied to wellhead 40 by various sources (e.g., oceancurrents, waves, platform 20, LMRP 50, BOP 30, etc.). As a result, it isdesirable to determine and monitor the strain on conductor 60 throughits term of service to avoid potential failures and losses.

Conventional systems for monitoring the strain on a conductor (e.g.,conductor 60) typically involve the installation of accelerometers alongthe wellhead 40, BOP 30, LMRP 50, or elsewhere to measure the movementof these corresponding components. The measured movements are then usedto calculate the amount of strain experienced by conductor 60. Toperform this calculation, it is necessary to define a point or depth 5below the mud line where the sediment is sufficiently consolidated tofully support conductor 60 and prevent all bending or other movementthereof. Such a point (i.e., point 5) is sometimes referred to as the“point of fixity.” In the embodiment of system 10 shown of FIG. 1, thevertical distance measured from the mud line to the point of fixity 5along conductor 60 is schematically shown as depth D₅. However,determining depth D₅ is difficult, especially in subsea applications,where the sea floor 13 and conductor 60 can be located over a mile belowthe sea surface 12. Consequently, indirectly determining the strainexperienced by a conductor via calculations relying on accelerometermeasurements and estimations of depth D₅ is often imprecise, and canlead to erroneous conclusions by well site personnel (e.g., thecalculated strain on conductor 60 is higher or lower than what isactually being experienced). As a result, embodiments disclosed hereininclude systems and methods for directly measuring the strain on aconductor (e.g., conductor 60), which offers the potential for moreinformed decisions by well site personnel regarding the remaining lifeor failure potential for the conductor 60 and related equipment.

Referring now to FIGS. 1 and 2, system 10 includes a strain monitoringsystem 100 for directly measuring and monitoring the strain experiencedby conductor 60 during drilling and/or production operations. As bestshown in FIG. 2, in this embodiment, strain monitoring system 100includes a sensor array 120 coupled to conductor 60 and a communicationunit 150 coupled to wellhead 40. Sensor array 120 and communication unit150 are electrically coupled such that data and information can becommunicated therebetween.

Referring now to FIGS. 2 and 3, sensor array 120 includes a plurality ofsensor assemblies 128 mounted to radially outer surface 60 c ofconductor 60. In this embodiment, sensor assemblies 128 are arrangedinto a plurality of axially stacked rows 122 a, 122 b, 122 c, 122 d.More specifically, in this embodiment, four (4) axially stacked rows 122a, 122 b, 122 c, 122 d are provided within array 120 with row 122 abeing the axially uppermost row, row 122 d being the axially lowermostrow, row 122 b being disposed immediately axially below row 122 a, androw 122 c being disposed axially between rows 122 b and 122 d. As shownin FIG. 2, rows 122 a, 122 b, 122 c are all disposed above the sea floor13 whereas row 122 d is disposed below the sea floor 13. However, ingeneral, any desired number of rows of sensor assemblies 128 can beprovided above and below the sea floor 13. For example, in someembodiments, the three axially lowermost rows 122 b, 122 c, 122 d aredisposed below the sea floor 13, and in other embodiments, all of therows 122 a, 122 b, 122 c, 122 d are disposed below the sea floor 13.

As best shown in FIG. 3, each row 122 a, 122 b, 122 c, 122 d includesfour (4) uniformly circumferentially-spaced sensor assemblies 128disposed about outer surface 60 c of conductor 60. As a result, thesensor assemblies 128 in each row 122 a, 122 b, 122 c, 122 d areangularly spaced 90° apart about axis 65. Although this embodiment ofsystem 10 includes four rows 122 a, 122 b, 122 c, 122 d of fouruniformly circumferentially-spaced sensor assemblies 128, in general,other specific numbers, arrangements, and spacing for the sensorassemblies (e.g., sensor assemblies 128) can be employed while stillcomplying with the principles disclosed herein. For example, in otherembodiments, more or less than four (4) sensor assemblies 128 may bedisposed within each row 122 a, 122 b, 122 c, 122 d, and sensorassemblies 128 may or may not be uniformly-circumferentially spacedabout outer surface 60 d. Although only one row 122 b is depicted inFIG. 3, it should be appreciated that each row 122 a, 122 c, 122 d isarranged in the same manner.

Referring now to FIG. 4, one sensor assembly 128 is shown, it beingunderstood that each sensor assembly 128 is the same. Each sensorassembly 128 is secured to the radially outer surface 60 c of conductor60 and includes a plurality of protective coatings or layers disposedthereon. As will be described in more detail below, these protectivecoatings protect the relatively fragile strain sensing elements withinassembly 128 during transport and installation of conductor 60, as wellas during drilling and production operations.

In this embodiment, sensor assembly 128 includes a strain sensor 130directly secured to radially outer surface 60 c with an adhesive 132, afirst or inner coating 134 disposed over and encasing sensor 130, and asecond or outer coating 136 disposed over and encasing inner coating 134and sensor 130. In general, sensor 130 can be any suitable sensor formeasuring or detecting the strain on a surface including, withoutlimitation, a resistive strain gauge, a capacitive strain gauge, a fiberstrain gauge, a semiconductor strain gauge, or the like. In thisembodiment, sensor 130 is a resistive based strain gauge that includes ametallic foil pattern having a total of three (3) terminals forconnection to an electrical power source (however, it should beappreciated that such sensors may have more or less than threeterminals, such as, for example, two or four terminals while stillcomplying with the principles disclosed herein). When the foil patternis deformed (e.g., as a result of strain experienced by the supportsurface that the sensor is mounted to), the electrical resistance acrossthe foil pattern between two of the terminals changes, and this changein electrical resistance can be directly correlated to an amount ofstrain on the support surface (e.g., in some embodiments the electricalresistance can be related to the strain by a gauge factor which is knownand based on the particular type, size, etc. of strain sensor used). Insome embodiments, sensor 130 may comprise a load cell such has thosemanufactured and sold by Interface of Scottsdale, Ariz. (specificexamples including the model 1010) and Tovey Engineering of Phoenix,Ariz. (specific examples including the model SW10). In otherembodiments, sensor 130 may comprise a strain gauge used within apressure transducer such as those manufactured and sold by OmegaEngineering, Inc. of Stamford, Conn. (specific examples including thePX409 pressure transducer) and Honeywell International Inc. of MorrisTownship, N.J. (specific examples including the SPT series pressuretransducers). In still other embodiments, sensor 130 may comprise awireless surface acoustic wave (“SAW”) sensor such as those manufacturedby Syntonics L.L.C. of Columbia, Md. or by Applied Sensor Research &Development Corp. of Arnold, Md. Also, in some embodiments, sensor 130may be similar to one or more of those described in U.S. Pat. Nos.7,268,662, 7,434,989, 7,500,379, 7,791,249, 8,094,008, 8,441,168 andU.S. Pat. App. Pub. Nos. 2013/0130362 and 2014/0007692, wherein thecontents of each of the above references are incorporated by referencein their entirety for all purposes.

In addition, sensor 130 may comprise a strain gauge configured tomeasure or detect the strain on outer surface 60 c along either a singleaxis (e.g., an axis oriented parallel with axis 65, an axis disposedwithin a plane that is perpendicular to axis 65, or an axis that isdisposed somewhere between parallel and perpendicular to axis 65) oralong multiple axes all while still complying with the principlesdisclosed herein. In this embodiment, sensor 130 is configured tomeasure the strain on surface 60 c of conductor 60 along an axisoriented parallel to axis 65.

In this embodiment, sensor assembly 128 also includes a temperaturesensor 131 adjacent to strain sensor 130. In general, temperature sensor131 can be any suitable temperature sensing device or apparatus known inthe art, such as, for example, a thermocouple, a thermistor, athermometer (e.g., a resistive thermometer), etc. In this embodiment,temperature sensor 131 is positioned circumferentially adjacent tostrain sensor 130 as shown, however, in other embodiments, thetemperature sensor (e.g., temperature sensor 131) may be axially orradially adjacent to strain sensor 130. In addition, in this embodiment,each of the sensor assemblies 128 include both strain sensor 130 andtemperature sensor 131. However, in other embodiments, sensor assemblies128 may only include one of the strain sensor 130 and temperature sensor131, and in still other embodiments, some of the sensor assemblies 128may include both sensors 130, 131, and others of the sensor assemblies128 may include only one of the sensors 130, 131.

Adhesive 132 secures sensors 130, 131 to conductor 60. In general,adhesive 132 can comprise any adhesive suitable for use in subsea and/ordownhole environments (i.e., adhesives capable of withstanding theanticipated temperatures, pressures, etc. in the subsea and/or downholeenvironment). In this embodiment, adhesive 132 comprises an epoxy resin.An example of a suitable epoxy resin is a two-part epoxy available fromVishay Precision Group, Inc. of Raleigh, N.C. (specific examplesincluding, but not limited to M-Bond 610 adhesive and M-Bond AE-15adhesive), and HBM, Inc. of Marlborough, Mass. (specific examplesincluding, but not limited to EP-310S adhesive and X280 adhesive). Inaddition, in at least some embodiments, radially outer surface 60 c (orsimply the portion of outer surface 60 c that sensors 130, 131 will bemounted to) is subjected to a surface treatment prior to applyingadhesive 132. Specifically, in some embodiments, outer surface 60 c isshot blasted (e.g., with shot peen) to result in a white metal surfacefinish. The purpose of these surface treatments is to promote adhesionbetween adhesive 132 and surface 60 c, thereby promoting a securemounting for sensor 130, 131. Further, in embodiments where sensors 130,131 are arranged radially adjacent one another, additional adhesive 132may be disposed radially between sensors 130, 131 to secure sensors 130,131 to one another.

Referring still to FIG. 4, as previously described, sensors 130, 131 areencased and protected by a plurality of protective coatings 134, 136.Such coatings 134, 136 are designed to protect sensors 130, 131 fromdamage caused both by mechanical impact as well as contact withpotentially corrosive or damaging fluids (e.g., chemicals, saltwater,hydrocarbon fluids, etc.). Inner coating 134 is disposed immediatelyaround and over sensors 130, 131 such that it contacts both of thesensors 130, 131 as well as a region or portion 64 of outer surface 60 cimmediately surrounding sensor 130. In general, coating 134 can compriseany suitable coating material(s) configured to restrict the ingress ofwater, formation fluids, or other fluids from the area immediatelysurrounding conductor 60 toward sensors 130, 131. In addition, coating134 should also maintain a certain level of elasticity and deformabilityso that it does not interfere with the ability of sensor 130 (andpotentially also sensor 131) to deform under the influence of strainexperienced by conductor 60. For example, in this embodiment, coating134 has a tensile strength TS₁₃₄ that is equal to approximately 530 psi[or 3654 kPa], an elongation e₁₃₄ of 350%, and a Durometer A hardness of55. In addition, coating 134 exhibits minimal corrosion, adhesion loss,or softening when exposed to salt water and jet fuel. Further, in thisembodiment, inner coating 134 is an electrical insulator, and thus, isconfigured to shield sensors 130, 131 from outside electrical influencesduring operations. In some embodiments, coating 134 comprises multiplelayers of bonding material, TEFLON® sheet(s), metallic foil, carbonfiber, other coating agents, or combinations thereof. In thisembodiment, coating 134 comprises a resin material such as, for examplea two-part polysulfide Permapol® P-5 liquid polymer like PR-1770available from PPG Industries, Inc. of Sylmar, Calif.

In general, inner coating 134 can be applied to sensors 130, 131 in anysuitable manner, such as, for example, extrusion, smearing, rolling,spraying, etc. In addition, once inner coating 134 is applied to sensors130, 131 it can be cured in any suitable manner such as, for example, byradiative heat, ultraviolet (UV) light, etc. In some embodiments,coating 134 is cured involuntarily or naturally through an exothermicreaction; however, without being limited to this or any other theory,increasing the temperature by using heat lamps or applying the coatingin a warm environment may accelerate the curing process. It should beappreciated that the curing method and parameters may affect theresulting properties of coating 134, such as for, example, the hardness,flexibility, etc. One of ordinary skill would appreciate the propercuring methods and parameters which would result in the desiredproperties discussed above.

Referring still to FIG. 4, outer coating 136 is disposed immediatelyaround and over inner coating 134 such that it contacts both innercoating 134 and at least a region or potion 68 of outer surface 60 cimmediately surrounding inner coating 134. In general, coating 136 cancomprise any suitable coating material(s) configured to protect sensors130, 131 from damage caused by mechanical impacts. Such impacts mayoccur during transportation, handling, installation, and use ofconductor 60, and can include, impacting conductor 60 (particular theregion of outer surface 60 c proximate sensors 130, 131) with anotherobject. In some embodiments, outer coating 136 comprises one or morelayers of urethane, carbon fiber, fiberglass, metallic wiring, rubber,and/or other resins. In this embodiment, coating 136 comprises a resinmaterial such as, for example polyurethane compound like PR-1535available from PPG Industries, Inc. of Sylmar, Calif. In addition,because coating 136 is utilized to guard against physical impacts andother direct trauma to sensor assembly 128, it should also maintain acertain level of toughness—which is a measure of a material's ability toabsorb energy and plastically deform without fracturing or failing.Toughness can also be thought of as a combination of tensile strengthand elongation. For example, in this embodiment, coating 136 has atensile strength TS₁₃₄ that is equal to approximately 4500 psi [or31,030 kPa], an elongation e₁₃₆ of 500%, and a Durometer A hardness of90.

Therefore, in this embodiment, the tensile strength TS₁₃₆ and elongatione₁₃₆ of outer coating 136 is greater than the tensile strength TS₁₃₄ andelongation e₁₃₄ of inner coating 134, and the hardness of outer coating136 is greater than the hardness of the inner coating 134. Accordingly,outer coating 136 has a greater toughness than inner coating 134. As aresult, inner coating 134 is able to accommodate deformation of sensor130 (and potentially also sensor 131) and resist fluid ingress towardsensors 130, 131, while outer coating 136 is able to protect sensors130, 131 from mechanical impacts. Also, as can be determined from thespecific materials properties given above, the tensile strength TS₁₃₆ ofouter coating 136 is approximately 8.5 times greater than the tensilestrength TS₁₃₄ of inner coating 134, and the elongation e₁₃₆ of outercoating 136 is approximately 1.4 times the elongation e₁₃₄ of innercoating 134.

Referring still to FIG. 4, it is generally desirable to limit the radialdistance to which sensor assemblies 128 extend from conductor 60 toreduce the potential for sensor assemblies 128 to physically interferewith other equipment during operations (e.g., transportation, handling,installation, etc.). As a result, in this embodiment, outer coating 136has an outer surface 136 a disposed at a maximum distance R₁₂₈ measuredfrom radially outer surface 60 c of conductor 60. In this embodiment,radial distance R₁₂₈ preferably ranges from 0 to 0.5 inches; however,other values are possible (e.g., values above 0.5 inches). Typically,the upper limit of radial distance R₁₂₈ is determined by the maximumradial distance to which other components of conductor 60, such ascouplers, extend. Therefore, limiting radial distance R₁₂₈ such that itis equal to or preferably less than the radial distance of these othercomponents of conductor 60 prevents at least some engagement with sensorassemblies 128 during operations.

In general, coatings 134 and 136 can be applied in any suitable mannerin order to fully and sufficiently cover and encase sensors 130, 131 andinner coatings 134, respectively. Referring now to FIG. 5, in thisembodiment, inner coating 134 and outer coating 136 are applied in aplurality of strips 139, 140, respectively, that extend axially alongradially outer surface 60 c of conductor 60. As shown in FIG. 5, eachstrip 139 includes a first or upper end 139 a, a second or lower end 139b opposite upper end 139 a, and an axial length L₁₃₉ extending betweenends 139 a, 139 b. Axial length L₁₃₉ is sized such that each strip 139covers one of the sensors 130, 131 of each row 122 a, 122 b, 122 c, 122d. Specifically, one sensor 130 in each row 122 a, 122 b, 122 c, 122 dis axially aligned with a corresponding sensor 130 in each of the otherrows 122 a, 122 b, 122 c, 122 d. Similarly, one sensor 131 in each row122 a, 122 b, 122 c, 122 d is axially aligned with a correspondingsensor 131 in each of the other rows 122 a, 122 b, 122 c, 122 d. Eachstrip 139 extends axially over each of the axially aligned sensors 130,131. In addition, each strip 140 includes a first or upper end 140 a, asecond or lower end 140 b opposite upper end 140 a, and an axial lengthL₁₄₀ extending between ends 140 a, 140 b. Axial length L₁₄₀ is sizedsuch that each strip 140 covers one of the strips 139 (and thecorresponding sensors 130 covered thereby). Therefore, in thisembodiment, axial length L₁₄₀ is preferably equal to or greater thanaxial length L₁₃₉. Without being limited to this or any other theory,this arrangement of coatings 134, 136 has the added benefit ofpreventing free rolling of conductor 60 about axis 65 when it is restingon radially outer surface 60 c, such as might be the case during storageand transportation of conductor 60.

Referring now to FIGS. 2 and 5, each sensor 130 and each sensor 131 iscoupled to an electrical connector 126 mounted to outer surface 60 c. Inparticular, a plurality of electrical conductors 129 electrically couplesensors 130, 131 to connector 126. Preferably, each conductor 129extends between one of the sensors 130, 131 and connector 126 (note:only a single conductor 129 is shown extending across sensors 130 inrows 122 a, 122 b, 122 c, 122 d in FIG. 5 for simplicity). In thisembodiment, conductors 129 comprise TEFLON® insulated wires (i.e.,conductors 129 include wires insulated with polytetrafluoroethylene,perfluoroalkoxy, fluorinated ethylene propylene, or combinationsthereof); however, other coatings and insulation are possible. Also, inthis embodiment (where conductors 129 are coated in TEFLON®) it ispreferable to etch the insulation with a Fluorocarbon Etchant to promotea strong bond between the insulation and one or more of the coatings(e.g., coatings 134, 136, 137, etc.). For example, in some embodiments,conductor 129 insulation is etched with Tetra-Etch® available fromPolytetra of Mönchengladbach, Germany. In addition, in at least someembodiments, the insulation of conductors 129 is prepped to promotewaterproofing thereof in a manner suitable for such purposes as would beknown and appreciated by one of ordinary skill in the art. As is bestshown in FIG. 5, at least a part of each conductor 129 is encased by oneof the strips 139, 140 of coatings 134, 136, respectively. In addition,in this embodiment, additional coating material(s) 137 encases portionsof conductors 129 that are not proximate sensor assemblies 128. Withoutbeing limited to this or any other theory, coating 137 provides strainrelief for conductors 129 as well as protection from egress ofconductors 129 and connector 126. Coating 137 may be the same ordifferent as coating 136 or coating 134 while still complying with theprinciples disclosed herein. In some embodiments, at least a portion ofconductors 129 that extend above the sea floor 13 are not encased bycoatings 134, 136, or 137 while still complying with the principlesdisclosed herein. In general, electrical connector 126 can be anysuitable electrical connector for coupling and transferring power, data,communication signals, or combinations thereof between sensorsassemblies 128 and other components (e.g., communication unit 150described in more detail below). In this embodiment, connector 126comprises a dry mateable electrical connector 126 mounted to radiallyouter surface 60 c.

In general, strips 139, 140 of coatings 134, 136 can be disposed onouter surface 60 c of conductor 60 by any suitable method while stillcomplying with the principles disclosed herein. However, as best shownFIG. 6, in this embodiment each strip 140 of outer coating 136 is formedby constructing or forming a mold 145 around one sensor 130 of each row122 a, 122 b, 122 c, 122 d after inner coating 134 is applied and cured.Mold 145 includes an inner cavity 146 sized and shaped to correspondwith the desired size and shape of each strip 140. Therefore, cavity 146has a total axial length (with respect to axis 65) that is equal tolength L₁₄₀, previously described. In addition, mold 145 includes anupper end 145 a, a lower end 145 b, an outlet 149 at upper end 145 a,and an inlet 147 at a lower end 145 b. Both inlet 147 and outlet 149provide access to cavity 146. To fill mold cavity 146, an injector 143is connected to inlet 147 and injects the material(s) making up outercoating 136 from a supply 141 into cavity 146 in at least a semi-liquidstate. Simultaneously with the injection of outer coating 136 intocavity 146 at inlet 147, a vacuum or negative pressure is created atoutlet 149 with a vacuum pump 148, thereby creating a pressuredifferential across cavity 146 between inlet 147 and outlet 149. As aresult, injected coating 136 is drawn up (via the differential pressure)within cavity 146 from inlet 147 toward outlet 149. After cavity 146 hasbeen completely filled, mold 145 is removed and outer coating 136 iscured in any suitable manner such as, for example, by radiative heat,ultraviolet (UV) light, or placing coating 136 in a warm environment ofapproximately 80-130° F. As is similarly explained for inner coating134, it should be appreciated that the curing method and parameters mayaffect the resulting properties of coating 136, such as for, example,the hardness, flexibility, etc. One of ordinary skill would appreciatethe proper curing methods and parameters which would result in thedesired properties discussed above. In addition, it should beappreciated that strips 139 of inner coating 134 may be formed through asimilar process to that described above for strips 140 while stillcomplying with the principles disclosed herein.

Referring now to FIG. 7, an external gauge ring 180 is disposed aboutconductor 60 axially below sensor array 120 to clear sediment in advanceof array 120 during insertion of conductor 60 into the sea floor. Inparticular, in this embodiment, ring 180 includes a first or upper end180 a, a second or lower end 180 b opposite upper end 180 a, a radiallyouter surface 180 d extending between ends 180 a, 180 b, and a radiallyinner surface 180 c extending between ends 180 a, 180 b. In thisembodiment, inner surface 180 c is cylindrical and engages radiallyouter surface 60 c of conductor 60. Outer surface 180 d includes adownward facing frustoconical surface 184 at lower end 180 b and anouter cylindrical surface 182 extending axially between frustoconicalsurface 184 and upper end 180 a. Outer cylindrical surface 182 extendsto a maximum radius R₁₈₀ measured radially from outer surface 60 c thatis preferably equal to or greater than the radius R₁₂₈ of sensorassemblies 128. In at least some embodiments, radius R₁₈₀ is preferablyless than the maximum radial distance to which other components ofconductor 60, such as couplers, extend to avoid interference by ring 180during installation and handling of conductor 60 as previously describedabove. In this embodiment, radius R₁₈₀ is preferably less than 0.5inches. In general, gauge ring 180 may be installed on radially outersurface 60 c in any suitable manner while still complying with theprinciples disclosed herein. For example, ring 180 may be secured toouter surface 60 c through welding, adhesive, securing members (e.g.,bolts, rivets, etc.), interference fit, or combinations thereof.

Referring now to FIGS. 8 and 9, during insertion of conductor 60 intothe sea floor 13, frustoconical surface 184 of gauge ring 180 engageswith sediment and directs it radially away from radially outer surface60 c of conductor 60 and thus also away from the trailing sensor array120. Because radius R₁₈₀ is preferably equal to or larger than radiusR₁₂₈ of sensor assemblies 128 within array 120 (FIG. 7), ring 180 pushessediment is radially beyond the reach of sensor assemblies 128 by asconductor 60 is advanced into sea floor. Therefore, the installation ofgauge ring 180 offers the potential to reduce excessive engagementbetween the sediment below the sea floor 13 and sensor array 120, whichcan prevent damage to array 120 during conductor 60 installationoperations.

Referring again to FIG. 2, communication unit 150 is received within areceptacle 46 mounted to a radially extending mounting bracket 44extending from wellhead 40. Communication unit 150 is configured toreceive data from each of the sensors 130, 131 within sensor array 120(e.g., strain measurements, temperature measurements, etc.) duringdrilling and/or production operations, and transmit that received datato a remote surface location. The remote surface location may be anylocation that is removed from wellhead 40 and system 100, and mayinclude any suitable location for receiving data such as, for example, acontrol room. In this embodiment, the remote surface location isdisposed on platform 20. In this embodiment, communication unit 150includes a wet mateable electrical connector 154 coupled to connector126 with a cable 127. As previously described above, connector 126 iselectrically coupled to sensors 130 in array 120 via conductors 129. Theconnection between cable 127 and connector 154 may be made up by aremote operated vehicle (ROV) subsea or may be made up by well sitepersonnel at platform 20.

Communication unit 150 also includes a wireless transmitter 152configured to communicate, via wireless signals 160, with the remotesurface location (e.g., platform 20). In general, wireless signals 160can comprise any suitable wireless communication signal forcommunication across atmospheric or oceanic space. For example, signals160 may comprise acoustic waves, radio waves, light waves, etc. In thisembodiment, signals 160 comprise acoustic signals. Transmitter 152 isconfigured to both transmit and receive wireless signals (e.g., signals160) during operation, and thus, communication unit 150 is configured tosend and receive signals to and from both sensor array 120 and theremote surface location (e.g., platform 20).

In this embodiment, communication unit 150 is configured to receive rawdata from sensors 130, 131 (e.g., electrical resistance, voltage,impedance, etc. readings from sensors 130, 131), calculate the resultingstrain, temperature measurements, respectively, from the raw data, andthen communicate the strain, temperature measurements to the remotelocation. Accordingly, communication unit 150 includes a processorconfigured to execute software stored on a memory.

Referring again to FIGS. 1-4, during drilling and/or productionoperations (i.e., following installation of systems 10, 100), any strainexperienced by conductor 60 (particularly on outer surface 60 c) causesdeformation of sensors 130 within array 120. The sensors 130 then outputsignals that include changes in at least one parameter as a result ofthe deformation (e.g., resistivity). This raw data signal is then routedto communication unit 150 via electrical conductors 129, connector 126,and cable 127, where it is then translated into a measurement of strainon conductor 60. The strain measurements communicated to communicationunit 150 are then communicated wirelessly to platform 20 viacommunication signals 160. In at least some embodiments, strainmeasurements are taken at a sufficient sampling frequency in order forwell site personnel to characterize cyclic loading conditions onconductor 60. In addition, in some embodiments, the data output fromsensors 130 and/or stored and communicated by communication unit 150 maybe sufficiently compressed through known methods to allow for moreefficient transmission and analysis thereof.

While embodiments disclosed herein have focused on the measurement ofstrain on the outermost conductor tubular (e.g., conductor 60), itshould be appreciated that other embodiments can also be utilized tomeasure and monitor the strain on other tubulars, such as, for example,other casing or conductor tubulars disposed within the outermostconductor of an oil and gas well. For example, referring now to FIG. 10,another offshore system 200 for drilling and/or producing subseawellbore 11 is shown. System 200 is substantially the same as system 10,previously described, and thus, corresponding components are given thesame reference numerals and the following description will focus on thedifferences between systems 10, 200. Specifically, in addition to thecomponents of system 10, system 200 includes a second or inner conductor210 extending concentrically within conductor 60 along axis 65. Innerconductor 210 includes a first or upper end 210 a coupled to wellhead40, a second or lower end (not shown) disposed within wellbore 11, aradially outer surface 210 c extending axially from end 210 a, and aradially inner surface 210 d also extending axially from end 210 a. Asshown in FIG. 10, when inner conductor 210 is concentrically disposedwithin conductor 60, an annulus 205 is formed between radially innersurface 60 d of conductor 60 and radially outer surface 210 c of innerconductor 210.

Referring now to FIGS. 10 and 11, system 200 also includes a strainmonitoring system 220 for directly measuring and monitoring the strainexperienced by conductor 210 during drilling and/or productionoperations. System 200 may include strain monitoring system 220 eitherin addition to or in lieu of strain monitoring system 100 previouslydescribed above. Strain monitoring system 220 includes a communicationassembly 230 mounted to radially outer surface 60 c of conductor 60 anda strain measurement assembly 260 mounted to radially outer surface 210c of inner conductor 210.

As is best shown in FIG. 11, communication assembly 230 is a ring-shapedmember that extends circumferentially about the radially outer surface60 c of conductor 60. Assembly 230 includes and houses a plurality ofacoustic transducers 232 that are circumferentially spaced about axis 65along surface 60 c. Communication assembly 230 can be secured to outersurface 60 c of conductor 60 through any suitable method while stillcomplying with the principles disclosed herein. For example, in someembodiments, communication assembly 230 is a clam shell style memberthat includes two circumferential halves that are joined by a hinge (notshown) thereby allowing assembly 230 to be closed about radially outersurface 60. In other embodiments, assembly 230 is welded or bolted toradially outer surface 60 c. In still other embodiments, assembly 230 issecured to radially outer surface 60 c with an interference fit or anadhesive.

Each transducer 232 includes one or more piezoelectric elements thatallow each transducer 232 to generate acoustic signals (e.g., acousticwaves) in response to the receipt of input electrical signals (i.e.,electric current), and further, to output electrical signals (i.e.,electric current) in response to the receipt of input acoustic signals.Accordingly, each transducer 232 can be referred to as being a“piezoelectric” transducer. In this embodiment, each transducer 232 isconfigured to generate and receive acoustic signals having frequenciesbetween 100 MHz and 2000 MHz; however, other frequency ranges arepossible. In general, each piezoelectric transducer 232 can be anysuitable piezoelectric transducer known in the art while still complyingwith the principles disclosed herein, and in some embodiments mayinclude transducers that are configured to communicate with othernon-acoustic wireless signals, such as, for example, optical signals,radio frequency (RF) signals, WiFi, BLUETOOTH®, etc.

Power and/or communication signals (e.g., electromagnetic signals, lightsignals, etc.) routed to and from transducers 232 in communicationassembly 230 may be carried by a conductor 236, shown in FIG. 10.Conductor 236 is routed from communication assembly 230 along outersurface 60 c either to another communication device (e.g., communicationunit 150, previously described) or to some other remote location (e.g.,platform 20). In this embodiment, conductor 236 is routed to platform20. Conductor 236 is configured substantially the same as conductors129, previously described, and may include any suitable conductor, suchas, for example, wires or fiber optic cabling. In addition, conductor236 may include a plurality of individual conductive elements (notshown) that are each coupled to one of the transducers 232 at one endand a separate component (e.g., communication unit 150, device orcomponent disposed on platform 20, etc.) at an opposite end.

Referring still to FIGS. 10 and 11, strain measurement assembly 260 iscircumferentially disposed about the radially outer surface 210 c ofinner conductor 210. As a result, assembly 260 is disposed withinannulus 205. Strain measurement assembly 260 generally includes aprotective outer ring member 262, and a plurality of strain sensorassemblies 128 (which may potentially include temperature sensor 131 asdescribed above), each being the same as previously described above.Sensor assemblies 128 are mounted to and are circumferentially spacedabout radially outer surface 210 c. As a result, assemblies 128 areconfigured to measure the strain (and potentially temperature) on innerconductor 210 during operations. In addition, in this embodiment,assembly 260 includes a power storage and delivery unit 264 (referred tomore simply herein as “power unit 264”) and a communication transducer266. Each of the sensor assemblies 128, power unit 264, and transducer266 are coupled (e.g., electrically or otherwise) to one another withone or more conductors 268 extending along or proximate to radiallyouter surface 210 c.

Referring now to FIGS. 11 and 12, ring member 262 provides a protectiveouter shell to the other components of strain measurement assembly 260during manufacturing, transportation, installation, and productionoperations for conductor 210. As best shown in FIG. 12, member 262includes a first or upper end 262 a, a second or lower end 262 b, aradially outer surface 262 c, and a radially inner surface 262 d. Anannular recess 263 extends radially inward from radially inner surface262 d. Recess 263 contains and houses each of the sensor assemblies 128,power unit 264, transducer 266, and conductor(s) 268 during operations.As with communication assembly 230, ring member 262 may be secured toradially outer surface 210 c of inner conductor 210 through any suitablemethod, such as, for example, welding, bolting, interference fit,adhesive, clamping, etc. In this embodiment, member 262 is a clam-shelltype member that includes two circumferential halves joined by a hinge(not shown). In at least some embodiments, recess 263 is sealed from theenvironment in annulus 205. Such a seal may be achieved and maintainedin any suitable manner while still complying with the principlesdisclosed herein. For example, in at least some embodiments, a pair ofannular seal assemblies (not shown) are disposed on radially innersurface 262 d, with one above recess 263 and the other below recess 263.Each seal assembly may include an annular seal gland extending radiallyinward from radially inner surface 262 d and a sealing member (metallic,non-metallic, compliant, etc.) disposed therein that engages radiallyouter surface 210 c when member 262 is installed on conductor 210.

Referring still to FIGS. 11 and 12, as previously described, each sensorassembly 128 disposed within recess 263 is configured substantially thesame as described above for strain monitoring system 100. Specifically,as best shown in FIG. 12, each sensor assembly 128 includes a strainsensor 130 (and possibly a temperature sensor 131) that is encased by aninner coating 134, which is further encased by an outer coating 136.Sensor 130 (and sensor 131 if applicable) and coatings 134, 136 are thesame as previously described above, and thus, a detailed description isomitted for conciseness. Each of the sensors 130 (and sensors 131 ifapplicable) of assemblies 128 is coupled to power unit 264 andtransducer 266 through conductor(s) 268 as previously described. Asshown in FIG. 11, in this embodiment, a total of four (4) sensorassemblies 128 are disposed about radially outer surface 210 c, and eachsensor assembly 128 is uniformly-circumferentially spaced such that eachassembly 128 is circumferentially spaced approximately 90° from eachimmediately adjacent sensor assembly 128. However, as previouslydescribed above, sensor assemblies 128 need not beuniformly-circumferentially spaced about radially outer surface 210 c,and more or less than four (4) sensor assemblies 128 may be includedwhile still complying with the principles disclosed herein.

Communication transducer 266 is configured substantially the same astransducers 232 of communication assembly 230. Therefore, transducer 266is configured to generate acoustic signals (e.g., acoustic waves) inresponse to the receipt of input electrical signals (i.e., electriccurrent), and further, to output electrical signals (i.e., electriccurrent) in response to the receipt of input acoustic signals. In thisembodiment, transducer 266 is configured to communicate wirelessly withany one or more (or all) of the transducers 232 through annulus 205 andconductor 60 (i.e., across surfaces 60 d, 60 c). In general, one or more(or all) transducers 232 receive electric signals (i.e., an electriccurrent) from conductor 236, converts the electric signals into acousticsignals 238 (i.e., acoustic waves 238), and outputs the acoustic signals238 to transducer 266. In addition, transducer 266 receives acousticsignals (i.e., acoustic signals 238 output from transducer(s) 232),converts the acoustic signals into electric signals (i.e., an electriccurrent), and outputs the electric signals to power unit 264 and/orsensors 130 (e.g., through conductors 268). Further, transducers 266receives electric signals from one or more of the sensors 130, convertsthe electric signals into acoustic signals 239 (i.e., acoustic waves239), and outputs the acoustic signals 239 to one or more of thetransducers 232. In addition, one of more of the transducers 232 receiveacoustic signal 239 (i.e., acoustic waves 239 output from transducer266), converts the acoustic signals 239 into electric signals, andoutputs the electric signals to conductor 236. In some embodiments, anadditional conversion unit (or multiple conversion units) is disposedwithin recess 263 and is configured to convert electrical signalsreceived from transducer 266 into a different signal format forsubmission to sensors 130 and/or power unit 264 as well as to convertsignals received from sensors 130 and/or power unit 264 into electricalsignals (e.g., when the signals received from sensors 130 and/or powerunit 264 are other than electromagnetic signals) for submission totransducer 264. Such a conversion unit would be particularly useful forembodiments where sensors 130 are coupled to transducer 266 through awireless connection (e.g., RF, acoustic, WiFi, etc.). In addition, itshould be appreciated that communication transducers 266, 232 mayoperate in substantially the same manner to communicate signals from thetemperature sensors 131 if such sensors are included in one or more ofthe sensor assemblies 128 as described above.

Further, during communication operations between transducer(s) 232 andtransducer 266, in at least some embodiments the signal(s) from platform20 and output from transducer(s) 232 are of a sufficient strength (i.e.,the signals are strong enough account for expected attenuation due toenvironmental conditions) such that they provide the electrical powernecessary to run various components of system 100 (e.g., transducer 266,sensors 130, etc.). For example, in some embodiments transducer 266 maybe configured to receive some amount of electric energy that is takenfrom signals emitted from transducer(s) 232 which may then be stored inpower unit 264 and utilized to power transducer 266, and sensors 130 forall operations described herein. Alternatively, for some embodimentstransducer 266 may continuously receive power from transducer(s) 232through acoustic signals throughout operations which again may then beutilized to power transducer 266 and sensors 130, 131 for all operationsdescribed herein. In at least some of these embodiments, the acousticsignals for transferring power from transducer(s) 232 to transducer 266may be at a different frequencies or on different channels than othercommunication signals (e.g., through frequency-division multiplexing).In addition, in some embodiments acoustic communication betweentransducers 232, 266 may only occur in one direction at any given time(e.g., either from transducer(s) 232 to transducer 266 or fromtransducer 266 to transducer(s) 232) such as, for example, throughtime-division multiplexing. Alternatively, in other embodiments acousticcommunication between transducers 232, 266 may occur in both directionssimultaneously (e.g., simultaneously from transducer(s) 232 totransducer 266 and from transducer 266 to transducer(s) 232.)

Power unit 264 is configured to store and deliver electrical power toeach of the sensors 130, 131 within assemblies 128 as well as transducer266 during operations. Power unit 264 may comprise any suitable elementor device for storing and delivering electrical power, while stillcomplying with the principles disclosed herein, such as, for example, abattery, capacitor, a wireless power receiver, or combinations thereof.During operations, electrical power is delivered to and stored in powerunit 264 via the acoustic communication between transducer 266 and oneor more of the transducers 232 in the manner previously described above.

During strain measurement operations, sensors 130 measure the strain oninner conductor 210 in the same manner as described above and outputsignals (that include either strain measurement values or some othermeasured value indicative of the strain such as a change in electricresistivity) to communication transducer 266 through conductors 268.Transducer 266 then converts the received signals from sensors 130 intoan acoustic signal 239 and routes signal 239 through annulus 205 andconductor 60 where it is received by one or more of the transducers 232within communication assembly 230. The received acoustic signal 239 isthen converted back to an electromagnetic signal and routed to platform20 (or some other remote location or device as described above) throughconductor 236. During these operations, measurements or data may begenerated by sensors 130 either automatically based on a set andpredetermined time period (e.g., every minute, hour, day, week, etc.) orupon receipt of an interrogation signal originating from platform 20 orsome other remote location. Specifically, in some embodiments, aninterrogation signal is routed via conductor 236 from some other remotelocation (e.g., platform 20) to transducers 232 in assembly 230. Uponreceipt of the interrogation signal, one or more (or all) of thetransducers 232 convert the electromagnetic signal into an acousticinterrogation signal 238 which is then routed across conductor 60 andannulus 205 to transducer 266, which receives and converts signal 238back to an electromagnetic interrogation signal in the manner previouslydescribed above. Thereafter, the newly converted interrogation signal isrouted through conductors 268 to one or more (or all) of the sensors 130which then take a reading of the strain on inner conductor 210 andoutput a measurement signal as described above. It should be appreciatedthat the communication operations with temperature sensors 131 issubstantially the same as discussed above for strain sensors 130.

During these communication operations, at least partiallycircumferential and axial alignment between transducer 266 and at leastone of the transducers 232 is preferred to allow for effectivecommunications therebetween. In this embodiment, circumferentialalignment is ensured since a plurality of transducers 232 are providedcircumferentially about radially outer surface 60 c. Thus, no matterwhere transducers 266 is located circumferentially along radially outersurface 210 c of inner conductor 210, it will be at least partiallycircumferentially aligned with one of the transducers 232. Axialalignment of assemblies 230, 260 is ensured by careful placement thereofalong conductors 60, 210, respectively, and is facilitated by the factthat both conductors 60, 210 are coupled to wellhead 40 at known (ordeterminable) axial positions.

In the manner described, through use of a strain monitoring system inaccordance with the principles disclosed herein (e.g., system 100),direct measurement and monitoring of the strain experienced by awellhead conductor (e.g., conductor 60) is possible. As a result, wellsite personnel are able to determine whether the conductor is nearing afailure event due to excess strain, and can therefore take appropriateaction to avoid the ultimate failure and mitigate any damage potentiallycaused thereby.

While preferred embodiments have been shown and described, modificationsthereof can be made by one skilled in the art without departing from thescope or teachings herein. The embodiments described herein areexemplary only and are not limiting. Many variations and modificationsof the systems, apparatus, and processes described herein are possibleand are within the scope of the disclosure.

For example, while embodiments of the strain monitoring system 100 havebeen described for use in an offshore drilling and/or production system10, it should be appreciated that embodiments of the strain monitoringsystem 100 disclosed herein may be utilized on a land based drillingand/or production system while still complying with the principlesdisclosed herein. In addition, while embodiments of the communicationunit 150 disclosed herein have been described as receiving raw dataoutput from sensors 130 and then converting that raw data into strainmeasurements for communication to the remote surface location (e.g., onplatform 20), it should be appreciated that in other embodiments,sensors 130 determine the strain on conductor 60 from the measuredparameter(s) and then route these determined strain measurements tocommunication unit 150 via conductors 129, connector 126, and cable 127as previously described. Also, in still other embodiments, the raw dataout put from the sensors 130 is converted into a measurement of strainon conductor 60 at the remote surface location (e.g., at platform 20).Further, although communication unit 150 as described here in wirelesslycommunicates strain measurements to the remote location in real time ornear real time, in other embodiments, the communication unit (e.g.,communication unit 150) simply stores all received data for laterretrieval to the remote surface location (e.g., platform). For example,in some embodiments, communication unit 105 stores data and is retrievedto the sea surface 12 by an ROV. Still further, while embodiments ofstrain measurement assembly 260 have included a transducer 266 forcommunication with one or more transducers 232 in communication assembly230, it should be appreciated that in other embodiments, sensors 130themselves may directly communicate with transducers 232 without the aidof a transducers 266. For example, in some embodiment, each sensor 130may include a wireless transceiver which is configured to produce anacoustic signal for transmission across annulus 205 and conductor 60 forreceipt by one or more of the transducers 232. Also, it should beappreciated that embodiments for measuring and monitoring the strain onan inner conductor (e.g., such as conductor 210 and the embodiment shownin FIGS. 10-12) may be utilized along with an embodiment of a strainmonitoring system for measuring and monitoring the strain on an outerconductor (e.g., such as conductor 60, and the embodiment of FIGS. 1-5).When such assemblies and systems are utilized together, communicationassembly 230 may additionally function as a collection point formeasurement signals not only from sensors 130 disposed on radially outersurface 210 c of inner conductor 210, but may also collect signals fromsensors 130 disposed on radially outer surface 60 c of outer conductor60. It should further be appreciated that communication unit 150 can bemounted anywhere proximal to wellhead 40 or other similarly situatedcomponents (e.g., production tree) and need not be directly mounted towellhead 40 as previously described above. While embodiments disclosedherein include sensor assemblies 128 that are all configured the same,it should be appreciated that other embodiments include sensorsassemblies 128 that are configured differently (e.g., different sensortypes, different coating arrangements, thicknesses, types, etc.) whilestill complying with the principles disclosed herein.

Accordingly, the scope of protection is not limited to the embodimentsdescribed herein, but is only limited by the claims that follow, thescope of which shall include all equivalents of the subject matter ofthe claims. Unless expressly stated otherwise, the steps in a methodclaim may be performed in any order. The recitation of identifiers suchas (a), (b), (c) or (1), (2), (3) before steps in a method claim are notintended to and do not specify a particular order to the steps, butrather are used to simplify subsequent reference to such steps.

What is claimed is:
 1. A system, comprising: a tubular member includinga radially outer surface; and a sensor assembly comprising: a strainsensor coupled to the radially outer surface of the tubular member; afirst coating having a first hardness and a first tensile strength,wherein the first coating encases the strain sensor and at least part ofthe radially outer surface of the tubular member; a second coatinghaving a second hardness that is greater than the first hardness and asecond tensile strength that is greater than the first tensile strength,wherein the second coating encases the first coating and at leastanother part of the radially outer surface of the tubular member.
 2. Thesystem of claim 1, wherein the strain sensor assembly extends radiallyoutward to a distance from the radially outer surface of the tubularmember that is less than about 0.5 inches.
 3. The system of claim 1,further comprising: an electrical conductor that is coupled to thestrain sensor and extends along the radially outer surface of thetubular member, wherein the second coating encases at least a portion ofthe electrical conductor; and an electrical connector that is coupled tothe electrical conductor and disposed on the radially outer surface ofthe tubular member.
 4. The system of claim 1, wherein the first coatingis an electric insulator and is configured to restrict contact of liquiddisposed around the tubular member with the strain sensor; and whereinthe second coating comprises one of at least one of resin, carbon fiber,and rubber.
 5. The system of claim 1, further comprising an externalgauge ring disposed about the radially outer surface of the tubularmember, axially below the sensor assembly; wherein the external gaugering includes a frustoconical lower surface and a radially outersurface; and wherein the radially outer surface of the external gaugering is radially outward from the second coating of the sensor assembly.6. The system of claim 1, further comprising a communication unit incommunication with the strain sensor; wherein the communication unit isconfigured to communicate with a remote surface location via a wirelesssignal.
 7. The system of claim 6, further comprising: a temperaturesensor coupled to the radially outer surface of the tubular member;wherein the communication unit is in communication with the temperaturesensor.
 8. The system of claim 1, further comprising: an inner tubulardisposed within the tubular member such that an annulus is formedbetween the inner tubular and the tubular member, wherein the innertubular has a radially outer surface; a second strain sensor coupled tothe radially outer surface of the inner tubular; a first transducercoupled to the radially outer surface of the tubular member; a secondtransducer coupled to the radially outer surface of the inner tubular;wherein the second transducer is electrically coupled to the secondstrain sensor; and wherein the first transducer is configured towirelessly communicate with the second transducer across the annulus. 9.The system of claim 8, further comprising: a ring member disposed aboutthe radially outer surface of the inner tubular; wherein the ring memberincludes an annular recess, wherein the second strain sensor and thesecond transducer are disposed within the annular recess; and a powerunit disposed within the annular recess and configured to storeelectrical power and deliver electrical power to the second transducerand the second strain sensor.
 10. A method of measuring strain on afirst conductor for use in an oil and gas well, the method comprising:(a) measuring a strain on the first conductor with a first strain sensorcoupled to a radially outer surface of the first conductor; (b)protecting the first strain sensor during (a) with an outer coating; (c)routing data from the first strain sensor to a communication unit after(a); (d) wirelessly communicating with a remote surface location withthe communication unit after (c).
 11. The method of claim 10, wherein(a) comprises deforming the first sensor with the strain on the firstconductor; and wherein the method further comprises: (e) accommodatingthe deformation in (a) with an inner coating disposed between the outercoating and the first strain sensor; and (f) resisting contact betweenliquids disposed about the first conductor and the first strain sensorwith the inner coating.
 12. The method of claim 10, further comprising:(g) forcing the first conductor into a wellbore before (a); (h) engagingsediment in the wellbore during (g) with an external gauge ring disposedabout the first conductor below the first strain sensor; and (i) forcingthe sediment radially away from the radially outer surface of the firstconductor during (h).
 13. The method of claim 10, further comprising:measuring strain on a second conductor disposed within the firstconductor with a second strain sensor coupled to a radially outersurface of the second conductor; and (k) routing data from the secondstrain sensor across an annulus formed between the first conductor andthe second conductor.
 14. The method of claim 13, wherein (k) comprisesrouting data from the second strain sensor across the annulus with awireless signal.
 15. The method of claim 14, wherein the wireless signalcomprises an acoustic signal.